Over the past several years, there has been much discussion about the potential applications of synchrophasor technology, but there has not been as much information about how the technology can be used in practical applications today. As a recent adopter of synchrophasor technology, Oklahoma Gas & Electric Co. (OG&E) has discovered many useful applications that can be applied to any utility regardless of size.

When OG&E began using the technology, it did so not as a research and development or federally funded project, but simply because it had most of the necessary components already in place. By 2008, the utility had installed dozens of phasor measurement units (PMUs). Many of these were installed at locations that also provided the high-speed communications backbone necessary to bring back the data. OG&E initiated a project to deploy a phasor data concentrator (PDC) and began using the technology. Since then, the utility has added more than 100 PMUs to the system, which provides monitoring of almost 30% of its transmission grid.

Getting Started

Many articles and technical papers have been written about synchrophasor technology and the potential benefits. Most, if not all, of the papers have been focused on solving regional or interconnection problems like wide-area visualization and blackout prediction. However, for OG&E — a mid-sized utility serving parts of Oklahoma and Arkansas — the direction was implementation of PMUs as a practical tool to locate and solve real-world operating problems at the individual utility level.

As with most new technology projects, an evolutionary process occurs when more is learned about the potential and practical applications of the technology. OG&E began with a single SEL-3306 PDC and eight SEL-421 line-protection relays doubling as PMUs. The live synchrophasor data was streamed through the PDC to the SEL SynchroWAVe software client for visualization. OG&E quickly realized the need for data from interesting events to be examined further. Unfortunately, the SynchroWAVe software did not allow viewing historical data at the time. Therefore, the utility developed a system to archive the data to a Microsoft SQL database along with a custom software application named PhasorView that displays the phasor data, both live and archived.

With the initial fleet of only eight PMUs on the 345-kV and 500-kV extra-high-voltage (EHV) system, OG&E made observations at a rate of 30 samples/sec and established a baseline for what would be considered normal operating conditions. The utility also joined the North American Synchrophasor Initiative (NASPI) and began streaming data to the host site at the Tennessee Valley Authority (TVA). This allowed OG&E to contribute its portion of the grid to the systemwide view of the U.S. Eastern Interconnection. For the first time, OG&E was able to observe how events on its system affected the interconnection and vice versa.

Disturbance Analysis

One of the early observations was how transmission system faults sometimes can be seen to have very widespread impact. Faults at 138 kV and 69 kV are observable on the EHV system and can affect distribution customers 200 miles (322 km) away. To improve disturbance-analysis capabilities, OG&E linked the archived synchrophasor database to the operations control center's database of transmission disturbances. This was done so all disturbances can be quickly analyzed for impact to the system and to easily verify the protection system's performance.

From the synchrophasor data, OG&E can determine if a disturbance is cleared by high-speed or step-distance (delayed) tripping. The utility discovered delayed tripping occurred in places where high-speed tripping was expected. This prompted field investigations, which resulted in corrective actions to enable the primary high-speed protection functionality.

System Event Investigation

The next evolutionary steps called for the utility to add many more PMUs and to begin using the Grid Protection Alliance's openPDC to concentrate the phasor data. A custom action adapter was written to archive the data to the SQL server database. Since the majority of the 500 to 600 annual transmission disturbance events involve weather-related incidents, OG&E incorporated a geospatial overlay of the transmission system and substations, along with lightning and weather radar data. The utility can instantly discern if a transmission disturbance was storm or lightning related, and determine the area of impact. As a result, the synchrophasor system is now a utility-wide fault recorder, becoming the top-level overview for analyzing transmission disturbances. Engineers can locate the source of the disturbance quickly using the wide-area synchrophasor data and continue down to the substation-level digital fault recorder and digital relay data to investigate further.

One unique feature of OG&E's PhasorView software is that any and all data collected is accessible without specifying a new file or database as the data source. The user can look at any specified increment of live data or instantly zoom out to the last day, week, month or year. Any PMU, or combination of PMUs, can be selected either by check box or from the geographic information system portion of the program. Under the default PMU selection mode, the program automatically selects eight PMUs spread across the entire EHV system to provide a broad view. Once a disturbance is detected by voltage pull down, the user can zoom into the disturbance and select eight new PMUs with the most severe voltage pull down with one click of the mouse. This enables the user to locate the source of the disturbance and proceed with an investigation.

Equipment Failure Discovery

Another valuable use of synchrophasor data is the detection of equipment failure, most of which is not detectable by supervisory control and data acquisition (SCADA) monitoring systems. Many instances have been observed where the positive-sequence voltage magnitude spikes randomly or drops to 66% of nominal.

These were determined to be caused by loose connections at the safety switch or terminal cabinets, loose caps on renewable fuses, animal damage to wiring and blown potential transformer (PT) fuses. In some cases, a protection misoperation was associated with the failure. Even modern digital relays do not always detect these conditions, confusing the directional element logic or failing to detect the loss of potential.

If a particular substation has multiple bus or line PTs, loose primary connections or failing coupling capacitor voltage transformers can be detected. This is because the intermittent signal problem will manifest itself on every PT at the station. The best defense against these conditions is to have field personnel dispatched as soon as the problem is identified to correct the problem and prevent protective relay misoperations.

Stability Assessment

Traditional tools for stability assessment involve off-line simulation of various system conditions within a dynamic stability model. While useful, these models do not always capture the intricacies of an interconnected system. Shortly after bringing the first PMUs on-line, OG&E discovered strange voltage oscillations on the EHV system at a frequency of 0.2 Hz. The oscillations were most pronounced at one of the PMUs near a combined-cycle natural gas generation facility. The observed signal was strongest on the megavolt-ampere-reactive (MVAR) plot, so it was suspected to be a generation control problem.

Having visibility to snapshots of the event, including the specific dates and times it occurred, the engineers contacted the plant manager, asking if it corresponded with any of the daily plant operations. The plant manager indicated there was indeed a correlation and found the cause of the problem within a particular unit VAR control scheme. This generation unit startup procedure placed the unit in a VAR control mode that was subsequently switched by an operator to voltage control mode, once the unit was synchronized. This switch in control mode was the trigger that stopped the oscillations.

The plant was able to resolve the control issues with this particular unit and prevent further stability problems. Without the sensitive synchrophasor measurements, this anomaly would have gone undetected and potentially could have escalated into a more widespread system event.

Wind Generation Issues

OG&E, along with many other utilities in the Great Plains region, has a large wind generation resource potential. Many large-scale wind farm facilities varying in size from 100 MW to 250 MW have been brought on-line, with many more under development. Currently, the Southwest Power Pool generation interconnection queue is approaching 30 GW of wind resources, making it one of the most prominent sources of renewable energy in the United States. Determining how these vast resources will be integrated into the regional power grid proves to be a challenge, and synchrophasor technology is able to provide the tools necessary to do so in a reliable manner.

Each new wind farm facility brought on-line in the OG&E service territory is accompanied by PMU measurements at the point of interconnection. In December 2010, the utility began observing oscillations on the transmission system in a portion of the grid in northwestern Oklahoma. These oscillations were occurring during periods of high wind generation, above 80% of the nameplate capacity. The voltage oscillations observed were as high as 5% fluctuation at an oscillatory frequency of around 14 Hz. This level of voltage fluctuation exceeded standards for objectionable flicker, and it was confirmed the impact was observable to area distribution customers.

The problem has been localized to specific wind farms, and the utility is undergoing efforts with the turbine manufactures to resolve the problem. This phenomenon could not have been observed with traditional SCADA monitoring, and without synchrophasor technology, the problem would have taken much longer to identify and resolve. The benefit of having PMU measurements at the point of wind farm interconnection is to ensure customers receive clean power while maintaining the level of system stability necessary for reliable power system operation.

Operations Support

Another somewhat unexpected application is the usefulness of phasor data to many different groups within a utility. The information provides situational awareness to the control center operations, disturbance/misoperation analysis for protection engineers and troubleshooting information for field personnel. As the lines between these different groups begin to cross, members can achieve a common goal together.

One example is when an unusually high-voltage angle was observed between two buses, indicating system stress. This prompted further investigation by the protection engineers who found a major EHV transmission autotransformer had been taken out of service for maintenance. As a result, another key autotransformer was being overloaded. The engineers notified the control center; subsequently, transmission loading relief was instigated by the regional transmission operator to bring the loading down to safe levels and protect the autotransformer from damage.

Another example involved the energization of a new 100-MW wind generation facility. The collector substation had been energized with PMU measurements at the 138-kV high-voltage bus. However, the PMU measurements indicated nearly zero positive-sequence voltage at the bus. This prompted protection engineers to examine the protective relay data further, which exposed the presence of negative-sequence voltage instead of the expected positive-sequence voltage.

The engineers suspected a phasing problem during commissioning and field personnel determined that the A and C phases were swapped on the secondary potential circuit. The benefit of having synchrophasor data during commissioning is to proactively find problems like this before they can evolve into bigger problems.

Future Plans

With the benefits clear, OG&E intends to continue to connect PMUs anywhere the communications infrastructure will allow. It is believed synchrophasor technology will continue to complement traditional SCADA measurement of the power grid, providing added system observation capabilities and improving reliability for customers. Some believe PMU measurement capability eventually will expand to the entire power grid, and OG&E believes anticipated changes in grid operations will make it necessary to do so.

With the amount of available data from PMUs, it also will be necessary to implement automated routines that can detect system anomalies and correct them before they impact customers and the bulk electric power grid. Algorithms are currently in use and more are under development to analyze the data to detect failing equipment and oscillations that can affect system reliability and stability.

Synchrophasors provide the means to make the transmission grid smarter and improve reliability. OG&E is prepared to use the technology to the fullest extent and encourages other utilities to do the same.

Steven E. Chisholm (chishose@oge.com) is a distribution automation engineer at Oklahoma Gas & Electric Co. His primary role involves deployment of smart grid-related equipment. Due to his interests in programming, Chisholm is responsible for the database and software programming behind OG&E's PhasorView application. He earned a BSEE degree in 2008 and a master's degree in electrical and computer engineering in 2011 from Oklahoma Christian University.

Austin D. White (whitead@oge.com) is a senior engineer at Oklahoma Gas & Electric Co. He is currently responsible for transmission/substation protective system settings and coordination, disturbance event/misoperation analysis and system modeling/simulation. Recently, he has been leading the efforts to deploy a synchronized phasor measurement system for the utility. White earned a BSEE degree from Oklahoma Christian University in 2001, followed by a master's degree in engineering and technology management from Oklahoma State University in 2008. He is a licensed professional engineer in Oklahoma.

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